INVESTOR PRESENTATION - Spartan Delta Corp. (SDE: TSXV) March 26, 2021
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INVESTOR PRESENTATION Spartan Delta Corp. (SDE: TSXV) March 26, 2021
SPARTAN DELTA CORPORATE STRATEGY
Building a Sustainable Energy Company for Global Investors
DISCIPLINED CONSOLIDATOR
Building towards >100,000 BOE/d
WEST-CENTRAL ALBERTA DEEP BASIN – Liquids-Rich ALBERTA MONTNEY – Oil-Weighted
▪ Low base decline 200%
▪ Drill ready inventory with owned
▪ Drill ready inventory with owned infrastructure
infrastructure
▪ Organic growth with top tier Montney
▪ Asset sustaining capital
COMPANY OVERVIEW
Spartan Delta Corp.
ALBERTA MONTNEY:
▪ Oil-weighted Montney
focus
Capitalization (as at March 25, 2021) ▪ Additional consolidation
opportunities
Spartan Delta Corp. TSX-V SDE ▪ Oil and Liquids-Rich
Montney drilling upside
Share Price (1) $/sh 4.04
Market Capitalization (basic) (1) $MM 460.2
Common Shares Outstanding (basic) MM 113.9
Net Debt (as at Dec 31, 2020) (2) $MM 12.3
Estimated YE 2021 Net Debt (Surplus) (2)(3) $MM (115)
Insider Ownership (basic) % 13.5
Dilutive Instruments
Warrants, ITM Options and Share Awards (4) MM 21.2
(5) MM 6.5
Zero Coupon Convertible Note (maximum issuance)
Dilutive Proceeds $MM 26.3
Fully Diluted Shares Outstanding MM 141.6 WEST-CENTRAL DEEP BASIN:
▪ Cretaceous Oil and Liquids-
Rich Gas focus
▪ Additional consolidation
opportunities
▪ Spirit River and Cardium
drilling upside
March 26, 2021 3
1) Share price as at closing on March 25, 2021 4) Excludes ~1.10MM out-of-the-money Options with an exercise price of $4.08/sh
2) See “Non-GAAP Measures” in Disclaimers 5) Assumes maximum issuance at conversion of $7.67/sh
3) See “Forward Looking Statements” in Disclaimers
YE 2020 HIGHLIGHTS
Optimization of Production and Cost Reductions Generate Material Free Funds Flow in 2020
Actuals Q1 2020 Q2 2020 Q3 2020 Q4 2020 FY 2020
Crude Oil % 10% 1% 1% 1% 1%
Low-cost production optimization Current (3)
Condensate % - 4% 4% 4% 4% offset declines in H2
Natural Gas Liquids (NGLs) (1) % 7% 25% 26% 26% 26%
Natural Gas % 83% 70% 69% 69% 69%
Average Production boe/d 251 8,906 26,282 26,010 15,421
Operating Expenses $/boe 22.57 6.96 6.10 5.68 6.11
Transportation $/boe - 1.38 1.34 1.37 1.36
Royalties % 0.4% 6.5% 8.5% 10.5% 9.0%
Operating Netback $/boe (4.33) 5.90 8.32 9.59 8.46 18% reduction in OPEX since West-
Central Alberta Deep Basin
G&A $/boe 1.50 1.64 acquisition (7% reduction Q3 to Q4)
37.76 1.48 1.48
Interest $/boe (3.48) 0.23 0.26 0.19 0.21
Adjusted Funds Flow (2) $MM (1.5) 2.8 14.4 16.8 32.5
Capital Expenditure (net of A&D) $MM 0.38 1.0 1.2 14.0 16.8
Well Count # 0 0 0 4 4
Free Funds Flow (2) $MM (1.9) 1.7 13.1 2.8 15.7
Exit Net Debt (Surplus) (2) $MM (21.7) 26.2 14.5 12.3 12.3
March 26, 2021 4
1) See “Oil and Gas Advisories” in Disclaimers
2) See “Non-GAAP Measures” in Disclaimers
3) As of March 24, 2021
WEST-CENTRAL ALBERTA DEEP BASIN LIQUIDS-RICH DEVELOPMENT
Free Funds Flow Generating Core Area - Driven by Industry Leading Capital Efficiencies
West-Central Alberta Deep Basin Asset Characteristics
Tidewater BRC
185 mmscf/d Deep Cut
Top Quality Resource:
▪ Top tier, delineated liquids-rich Spirit River and condensate-rich
Cardium gas development
▪ Primary targets: Falher, Notikewin and Cardium sands
SDE O’Chiese Nees-Ohpawaganu’ck 10-09
▪ 425 net risked Spirit River and Cardium locations (1) 230mmscf/d Deep Cut (25% WI)
CVE Sand Creek
Land: 75 mmscf/d
(9.6% WI)
SDE 5-5
▪ >54,000 (2) net acres of delineated Spirit River and Cardium land 1,000 bbl/d
▪ Additional consolidation opportunities in the vicinity leveraging off CVE Alder
75 mmscf/d
infrastructure advantage (20% WI)
SDE 2-10 SDE 13-5
20 mmscf/d 74 mmscf/d
Infrastructure:
▪ Significant owned and operated strategic infrastructure in place to SDE 9-3
SDE 5-3
grow production >40,000 boe/d with minimal incremental capital 45 mmscf/d
20 mmscf/d
SDE 6-21
▪ Deep-cut gas processing enhances margins on liquids recovery 40 mmscf/d
SDE 8-4
20 mmscf/d
▪ Direct tie-in to NGTL with optionality on liquids marketing
▪ Tangible operating cost savings as throughput increases over time
OBE Crimson
Low Decline Base Production: SDE 4-29 60 mmscf/d
350 bbl/d
▪ Current base decline of 19%
Material Free Funds Flow Driven by Low Sustaining Capital:
▪ Sustaining capital of $30 million vs. corporate NOI (3)(4) of $170 million
~$4,000/flowing barrel capital efficiency (1)
Spartan Working Interest Gas Plant Spartan Wells Pembina HVP / LVP
Third Party Gas Plant Spartan Pipelines Tidewater Pipelines
Spartan Compressor Station / Battery NOVA NGTL Keyera Pipelines
March 26, 2021 5
1) See “Oil and Gas Advisories” in Disclaimers 4) See “Non-GAAP Measures” in Disclaimers
2) As of December 31, 2020
3) Estimate, based on Spartan Budget Price Deck as defined on slide 36
YE2020 RESERVES HIGHLIGHTS
Extended Reach Horizontals (“ERH”) Drives Step Change in F&D and Development Economics
YE2020 West-Central Alberta Deep Basin Reserves Highlights:
Oil Natural Gas NGL's Total NPV10
▪ Spartan’s Year-End 2020 Reserves demonstrate the superior Reserves Category (MMbbl) (Bcf) (MMbbl) (MMboe) ($MM) (1)
economics of its West-Central Alberta Deep Basin core area: Proved Developed Producing 0.9 277.3 20.2 67.3 375.9
Total Proved 2.6 557.0 39.6 135.0 777.3
▪ Recycle Ratio (1) of 2.4x (TP) and 2.9x (TPP)
Total Proved + Probable 5.0 847.8 60.6 206.9 1,078.1
▪ F&D (1) of $3.94/boe (TP) and $3.35/boe (TPP)
▪ 99% of the Reserve NPV10 (1) is within the West- Total (MMboe) (1)
250
Central Alberta Deep Basin core area; newly acquired 206.9
Alberta Montney core area to be included in the next 200
reserves update
Reserves (MMboe)
150 135.0
▪ Reserve plan matches Spartan’s current business plan; modest
capital expenditures to maintain significant free cash flow:
100
67.3
▪ Optimized FDC (1) of $267MM (TP) and $417MM
(TPP); only 1.9x (TP) and 3.0x (TPP) of Spartan’s 50
current Adjusted Funds Flow (2) Guidance ($139MM)
0
▪ Highly economic and achievable development plan delivers PDP TP TPP
$620MM of NOI (2) after capital in McDaniel’s 5-year reserves
model
NPV10 ($MM) (1)
▪ 72% of booked and 56% of total inventory are now $1,200 $1,078
configured as ERH locations
$1,000
▪ Material future reserves growth potential remains unbooked: $777
NPV10 ($MM)
$800
▪ Only booked reserves in four main formations
(Cardium, Falher A, Falher B, and Notikewin) $600
$376
▪ Over 425 Spirit River and Cardium locations (1) remain $400
in inventory (>75% unbooked)
$200
▪ Spartan’s YE2020 Reserves do not include any values
$0
attributable to transactions announced in 2021 PDP TP TPP
March 26, 2021 6
1) See “Oil and Gas Advisories” in Disclaimers
2) See “Non-GAAP Measures” in Disclaimers
WEST-CENTRAL ALBERTA DEEP BASIN 2020 YE RESERVE AUDITOR MODEL
McDaniel’s TPP Bookings Generate $620 Million of NOI (2) After Capital Expenditure in First 5 Years
TPP Production Forecast YE 2020 TPP NOI (2) Summary (5yr McDaniel’s Forecast)
Achievable Development with Steady Production Growth TPP Development Generates Material Net Operating Income at Reserve Auditor Pricing
Spartan can show reserve and value growth for the next 5+ years:
▪ 101 Net locations booked (63 PUD, 38 PBUD), TP FDC (1) = $266.5MM, TPP FDC (1) = $417.3MM
▪ Additional 425 locations in inventory with strong economics (>75% unbooked)
▪ Ability to increase capital expenditures and accelerate growth within cash flow
March 26, 2021 7
1) See “Oil and Gas Advisories” in Disclaimers
2) See “Non-GAAP Financial Measures” in Disclaimers
WEST-CENTRAL ALBERTA DEEP BASIN INVENTORY SUMMARY
Robust Inventory with Years of Future Growth at High Rates of Return
Updated Inventory: YE2020 Inventory Summary (1)
▪ As at year end 2020, prior to acquisitions announced on February 16, 2021
Zone Booked Unbooked Total % ERH
▪ Rigorous review of every location within the West-Central Alberta Deep
Basin inventory Cardium 37 121 158 65%
Spirit River (2) 57 211 268 52%
▪ In 2020, Spartan reconfigured its reserves inventory to capture Extended Total Cardium & Spirit River 93 332 425 57%
Reach Horizontal (ERH) locations where available Other (6) 8 157 165 53%
Total 101 489 590 56%
Highly Economic and Efficient Inventory:
▪ Reconfiguring to ERH has made locations more economic. Compared with
1.0-mile locations, 2.0-mile extended reach horizontals:
▪ Require 1.25x more CAPEX
Cumulative Distribution of Location IRR (3)(5)
▪ 1.80x higher 1P/2P reserves By Booking Category
100%
▪ Results in 1.7x higher IRR (5) 90%
▪ YE2020 Inventory is now ~56% extended reach 80%
Percentage of Inventory (%)
▪ Spartan has identified ~200 net Spirit River and Cardium locations with IRRs 70%
(3)(5) exceeding 100%
60%
What Drives the Robustness of the Inventory? 50%
▪ High quality, over pressured reservoir with high liquids yield 40%
30%
▪ Infrastructure is built out: full cycle economics require little to no
infrastructure capital 20% 5 Year Plan | 13 net wells/yr | Mean IRR = 306%
Booked | 93 net wells | Mean IRR = 216%
▪ Deep cut processing enhances liquids recovery 10%
Unbooked | 218 net wells | Mean IRR = 111% (4)
▪ Field optimization since acquisition has reduced operating costs and 0%
0% 100% 200% 300% 400% 500%
increased margins
IRR (%)
March 26, 2021 1) Net locations rounded to the nearest whole number 4) Unbooked excludes Falher D/E and Wilrich
8
2) Spirit River includes Notikewin, Falher A/B/D/E and Wilrich 5) See “Non-GAAP Measures “in Disclaimers
3) Based on Spartan Budget Price Deck, as seen on slide 36 6) Other includes 8 Booked PRA locations, and all other zones in West-Central Alberta Deep Basin
WEST-CENTRAL ALBERTA DEEP BASIN SPIRIT RIVER TYPE WELL
Operational Efficiencies and ERH Drilling Drives Step Change in Well Economics
Highlights:
▪ Next 5-year estimated development capital efficiency (4): ~$4,000/boepd
▪ >88 locations with less than 10-month payout (4)
▪ Considerable room for future reserve growth: 22% booked
▪ Diversification potential through complementary zones (Falher D/E, Wilrich excluded)
▪ Diverse land base: 58% Crown / 42% IOGC
1P Type Curve and Economics (1)
Spirit River Single Well 1P Economics (2)
Inputs Tier 6+ Tier 5 Tier 3-4
1P Reserves Mboe 1,545 1,069 673
Gas MMcf 6,657 4,620 2,841
Cond Mbbl 52 36 22
NGLs Mbbl 383 201 131
% Liquids % 28% 22% 23%
DCET C$M $4,465 $3,912 $3,454
Average lateral length mi 1.9 1.7 1.4
Outputs
NPV10 C$M $8,692 $5,866 $3,186
1 IRR % 271% 221% 120%
Payout Years 0.6 0.7 1.2
Capital Efficiency $/boepd $3,044 $4,098 $5,611
(3)
Net Location Count # 37 31 71
% of Inventory % 21% 18% 41%
March 26, 2021 9
1) See “Oil and Gas Advisories” in Disclaimers, Type Curve prepared by McDaniel, Dec. 2020 4) See “Non-GAAP Measures” in Disclaimers
2) Based on Spartan Budget Price Deck as seen on slide 36; Jan 1, 2021 Effective Date
3) Includes Falher B, Notikewin and select Falher A locations
WEST-CENTRAL ALBERTA DEEP BASIN CARDIUM TYPE WELL
Over-Pressured Cardium Provides Compelling Condensate-Rich Economics
Highlights: Inventory IRR of Cardium
▪ Next 5-year estimated development capital efficiency (3): ~$5,000-6,000/boepd
▪ >107 locations with less than 1 year payout (3)
▪ 65% of inventory is booked as ERH
▪ Considerable room for future reserves growth: 24% booked
▪ Diverse land base: 63% Crown / 37% IOGC
1P Type Curve and Economics (1)
(2)
Cardium Average Tier Single Well 1P Economics
Inputs Tier 3 Tier 1
1P Reserves Mboe 963 579
Oil Mbbl 62 67
Gas MMcf 3,097 1,764
Cond Mbbl 36 19
NGLs Mbbl 349 199
% Liquids % 46% 49%
DCET C$M $4,222 $3,595
Average lateral length mi 1.9 1.4
Outputs
NPV10 C$M $6,803 $3,983
IRR % 212% 136%
Payout Years 0.7 0.9
Capital Efficiency $/boepd $5,357 $6,846
Net Location Count # 57 50
March 26, 2021 1) See “Oil and Gas Advisories “in Disclaimers, Type Curve prepared by McDaniel, Dec. 20 10
2) Based on Spartan Budget Price Deck as seen on slide 36; Jan 1, 2021 Effective Date
3) See “Non-GAAP Measures” in DisclaimersWEST-CENTRAL ALBERTA DEEP BASIN WINTER DRILLING RESULTS
Winter Drilling Program – Exceeding Expectations
Highlights:
102/16-23-045-09W5
▪ 8 well program: six extended reach horizontal Spirit River wells, one 2.0- Cardium, 2 mile HZ
SDE 10-09 Deep Cut Gas Plant
mile Cardium well and one 1.0-mile Spirit River 100/06-25-044-10W5
Falher B, 1.6 mile HZ
▪ 8 wells are now on production, with several wells producing at restricted
rates to manage declines and operational efficiencies
102/04-25-044-10W5
▪ 7 of the 8 locations feed the Spartan operated 10-09 deep cut gas plant Falher B, 2 mile HZ
103/04-25-044-10W5
▪ All operations were completed successfully under budgeted DCET cost Notikewin, 2 mile HZ
100/07-01-044-10W5
Spartan Production – Net Sales Falher B, 1.8 mile HZ
100/01-26-044-07W5
35,000 102/08-01-044-10W5
Notikewin, 2 mile HZ
Falher B, 1.8 mile HZ
30,000
102/01-16-043-09W5
Net Sales Production (boe/d)
Falher B, 1 mile HZ
25,000
20,000
15,000
10,000
5,000
DCET (1) IP30 (2) IP60 (3)
0
2020-10 2020-11 2020-12 2021-01 2021-02
($MM) (boe/d) (boe/d)
Q4/Q1 Program $3.8 1,523 1,642
Spartan Base Q4 Drilling Q1 Drilling
March 26, 2021 11
1) Average DCET over 8 well program; including 6 two-mile Spirit River wells, 1 Cardium two-mile and 1 single-mile Spirit River
2) Average IP30 Production Sales Estimates for 8 Spirit River wells
3) Average IP60 Production Sales Estimates for 6 Spirit River wellsSUMMARY OF RECENT ACQUISITIONS
Acquisition of High-Quality Assets Establishes Second Core Development and Consolidation Area
Spartan has entered into three definitive acquisition agreements which
execute upon its consolidation strategy.
Alberta Montney Core Area Entry Acquisitions: SDE Gold Creek
▪ Gold Creek Oil Montney with the corporate acquisition of Inception Exploration Processing Facility
▪ Simonette Liquids-Rich Montney and Spirit River with assets coming out of a CCAA
restructuring
Gold Creek
West-Central Alberta Deep Basin Core Area Expansion Acquisition: Simonette Gas Plant
▪ Willesden Green, Cardium and Spirit River Assets with production, royalties, facilities
and land
Summary of Acquisitions
Production - Feb 16, 2021 (22.5% Oil, 4.5% Condensate, 8% NGLs) boe/d 9,700
Proved Reserves (1) Mboe 91,517 Simonette
Proved plus Probable Reserves (1) Mboe 215,381
Run Rate Net Operating Income (2) $MM 50.0
Total Land net acres 235,393
Total Montney Land net acres 85,388
Total Net Drilling Locations (1) # 414
(1) # 343
Total Net Montney Drilling Locations
Metrics of Acquisitions SDE O’Chiese Nees-
Alder Gas Plant
Ohpawaganu’ck Gas Plant
Production - Feb 16, 2021 $/boe/d 15,247
Proved Reserves (1) $/boe 1.62
Proved plus Probable Reserves (1) $/boe 0.69
Sand Creek Gas Plant
Multiple of Run Rate Net Operating Income (2) x 2.95
Total Purchase Price
Cash consideration, after estimated adjustments $MM 18.4
Willesden
Common Shares $MM 96.7 Green
(3)
Convertible Unsecured Promissory Note (Principal - $50.0MM) $MM 25.0
Working Capital Deficit $MM 7.8
Spartan (Pre-acquisitions)
Total consideration (estimate) $MM 147.9
Inception Exploration
Simonette Acquisition
Willesden Green Acquisition
March 26, 2021 1) See “Oil and Gas Advisories” in Disclaimers
12
2) Run Rate NOI based on Spartan Budget Price Deck as seen on slide 36, See Non-GAAP Measures in Disclaimers
3) Convertible at Spartan’s election after second anniversary at greater of $7.67/sh or 10-day VWAP of SDE equity on conversion dateMATERIAL ENTRY INTO THE ALBERTA MONTNEY FAIRWAY
Introducing Spartan’s New Core Area for Development and Consolidation
Best in Class Resource: Spartan Montney Lands
Velvet Energy
▪ One of Canada’s most prolific plays with attractive economics Leucrotta Hammerhead Resources
across a broad range of commodity prices Pipestone Energy
Shell
▪ Delineated and repeatable development - well suited to
Paramount Resources
Spartan’s low-cost execution skill set Advantage
▪ Higher oil and liquids rates provide commodity diversification to Arc Kelt
NuVista
the business
Seven Generations
Distinction / Kiwetinohk
Tourmaline
Near-term Development Pathway to >25,000 boepd of Oil- XTO
Weighted Alberta Montney Production: Whitecap
Cenovus
▪ Deep inventory with drill ready locations Canadian Natural
Leucrotta
▪ Spartan owned infrastructure in place to accommodate growth Arc
without incremental spend Advantage Ovintiv
Kelt Tourmaline
▪ Multiple egress pathways provide flexible marketing options
Grande Prairie
Inception Acquisition (Gold Creek):
Pipestone
▪ Current Production ~4,200 boe/d (~53% liquids) (1)(3)
Gold Creek Velvet
▪ Infrastructure in place to grow to 20,000 boe/d Shell
Paramount
▪ Near-term focus of development NuVista CNRL
Hammerhead
Simonette Acquisition:
▪ Current production ~4,500 boe/d (17% liquids) (2)(3)
▪ Infrastructure in place to grow to 25,000 boe/d
Seven Whitecap
▪ Mid-term development focus Generations
January Land Acquisition: Ovintiv
XTO
▪ 26 sections of Montney rights Cenovus Distinction /
Simonette Kiwetinohk
▪ Future development potential upon expansion of infrastructure
footprint
March 26, 2021 13
1) 43% crude oil, 10% NGLs and 47% conventional natural gas
2) 4% crude oil, 9% condensate, 4% NGLs and 83% conventional natural gas
3) As of March 12, 2021GOLD CREEK MONTNEY DEVELOPMENT
Acquisition of Inception Exploration Anchors Second Core Development and Consolidation Area
Inception Asset Characteristics
CITY OF GRANDE PRAIRIE
Bezanson
Top Quality Resource:
▪ Top tier Montney asset in the core of the Alberta Montney Oil
Pipestone
development fairway
▪ >128 net risked Middle Montney locations (1)(2)
Land: SDE Battery & Gas Processing:
• 10,000 bopd
▪ >30,000 net acres of delineated Montney land • 5,000 bwpd
• 40 mmscf/d sour gas
▪ Additional consolidation opportunities in the vicinity leveraging off
infrastructure advantage
Infrastructure:
▪ Significant 100% working interest (“WI”) infrastructure in place to
grow production >20,000 boe/d with minimal incremental capital Elmworth
▪ Processing optionality: dual gas plant connection, ability to add third SDE Sales Compressor
connection with minimal capital
▪ Sales optionality: dual connection to NOVA and Alliance Gold Creek
▪ No minimum-volume processing commitments
▪ Many components already in place for a future Spartan gas plant
State of Readiness: SemCams Wapiti
CNRL Gold Creek
▪ Drill ready, multi-well pad development set to begin in 2021
Keyera Wapiti
Wapiti
Spartan Montney WI Lands Acquisition Montney Wells CNRL Gold Creek System
Montney Wells SemCams System
Acquisition Infrastructure Keyera System
March 26, 2021 1) See “Oil and Gas Advisories” in Disclaimers
14
2) Assumes 300m well spacing and scaling up of frac densityGOLD CREEK MONTNEY
Oil-Weighted Development Across a Well Delineated Land Base
▪ Over 160m of net reservoir situated in the over-pressured (>10 kPa/m) oil prone
fairway of the Alberta Montney
CITY OF GRANDE PRAIRIE
▪ De-risked future development with 21 horizontals drilled to date across land
base
▪ Single layer Middle Montney development; potential for “wine-rack” style
geometry currently being modelled with wells in both Middle and Lower Middle
Montney
Oil
▪ Evolution in completion design from 2013 to 2020 demonstrates significant
(>400 bbls/MMcf)
improvement in deliverability with implementation of tighter stage spacing and
increased tonnage
▪ 2021 budget includes 3-4 net wells in TWP 69-05W6 targeting the Middle and 8-36 HZ
Lower Middle Montney; finalizing completion designs for summer program A
A 100010307006W600 100041906905W600 100162606905W600 A’ A’
Gamma NPHI DPHI RESD Gamma NPHI DPHI RESD Gamma NPHI DPHI RESD
TOP
MNTN
Gas Condensate
(~50 bbls/MMcf)
MIDDLE
Montney
D2
Lower Spartan Montney WI Lands SDE Montney Wells Pressure Gradient
MIDDLE Industry Montney Wells
Montney
▪ 100/08-36-069-05W6 HZ drilled from 7-34 pad; on production Dec. 2019
LWR
▪ Cumulative oil to date >185 mbbls w/ peak monthly rate of 900 bbls/d
LOWER
Montney
▪ 1.8-mile lateral, completed with 160 stage 50t/stage multi-stage frac;
BELLOY
▪ Step change in results compared to offsets with 75 stages and lower tonnage
March 26, 2021
Middle Montney Landing Depth ▪ Basis for development in 2021/22 program 15SIMONETTE MONTNEY DEVELOPMENT
Acquisition of Simonette Asset Bolsters Second Core Development and Consolidation Area
Simonette Asset Characteristics
Undercapitalized, High-Quality Resource: Alliance Connection
▪ The Simonette asset represents a significant resource footprint within the
Alberta Montney fairway with delineated and attractive development
opportunities across liquids-rich, gas and oil prone horizons
Keyera Simonette
▪ Primary target of Middle Montney; Lower Montney has also been
identified as highly prospective
Kanata Simonette 13-11 Plant:
• 120mmscf/d capacity
▪ >214 net risked Middle Montney locations (1) • 30mmscf/d throughput
• 50% WI
Land:
▪ >54,000 net acres of delineated Montney land
▪ Additional consolidation opportunities in the vicinity leveraging off
infrastructure advantage
Infrastructure:
▪ 50% WI in a 120 mmcf/d natural gas plant allows for production growth
>25,000 boe/d
▪ Sales optionality: dual connection to NOVA and Alliance
Low Decline Base Production:
▪ Stable base decline ofSIMONETTE MONTNEY
Diverse Montney Opportunity Set Within a Large Underexploited Resource Base
▪ Over 100m net reservoir of Montney resource at predominantly higher than
normal reservoir pressure (> 10 kPa/m)
▪ De-risked future development with 38 horizontals (34 gas to liquids-rich and four
oil) drilled to date across 62,000 acres of Montney rights
4-34 HZ
▪ Analogue wells with lower landing depths in the Middle Montney demonstrate
potential for higher liquids yields in both gas and liquids fairways
▪ Modern completion design with increased length and tonnage in combination
with lower landing depth yield significant improvement in deliverability 9-18 PAD
Oil
▪ Additional opportunities identified in the Spirit River within the core of the asset (>100 bbls/MMcf)
A 100111606127W500 100133606127W500 100012906126W500
A’ A’
TOP Gamma NPHI DPHI RESD Gamma NPHI DPHI RESD Gamma NPHI DPHI RESD Gas
MNTN A (2021 GUIDANCE
Adjusted Funds Flow Sensitivities
2021 Guidance (1)(2) West-Central Alberta Deep Basin Assets Drive Robust Cash Generation:
▪ 100% of natural gas production priced at AECO
Average Production boe/d 35,500 - 37,500 ▪ West-Central Alberta Deep Basin sustaining capital (3) requirement:
Crude Oil % 4 26% reduction since acquisition in June 2020)
▪ Free Funds Flow (3) will be applied to continued consolidation of
Operating Netback (3) $/boe 12.74
quality assets at attractive metrics
Adjusted Funds Flow (3) $MM 139
(4) $MM 101
Capital Expenditures
Free Funds Flow (3) $MM 38
2021 Adjusted Funds Flow Sensitivity (1)(2)(3)
Net Debt (Surplus) (3) $MM (115)
WTI US$/bbl $50 $55 $60
Edm. Oil Diff US$/bbl $4 $4 $5
2021 Capital Allocation % Wells
Edm. Cond Diff US$/bbl $1 $1 $3
West-Central Alberta Deep Basin 65% 13 Conway Propane US$/GAL $0.65 $0.70 $0.75
Alberta Montney - Gold Creek 35% 4
FX US/C 1.27 1.26 1.25
$/GJ $2.50 $123 $132 $141
AECO $/GJ $2.75 $131 $139 $147
$/GJ $3.00 $138 $146 $154
March 26, 2021 18
1) See “Forward Looking Statements” and “FOFI” in Disclaimers 4) Excluding A&D
2) Based on midpoint production of 36,500 boe/d and Spartan Budget Price Deck as seen on slide 36
3) See “Non-GAAP Measures” in DisclaimersSPARTAN SUSTAINABILITY
Environmental, Social & Governance
Canada is a world leader with respect to producing sustainable energy responsibly
Environment:
▪ Spartan is committed to industry leading environmental practices:
▪ Spartan has ~400 solar panels, with solar power generation at nearly every pad site within its core operating area
▪ Spartan has participated in or operated 36 wells and one facility abandonment since March 2020 and progressed
towards reclamation certification on over 100 abandoned locations
▪ Achieved a 100% satisfactory rating with the AER in 2020 vs. industry average of 78%
▪ Spartan assets generated over 17,544 tCO2e credits in 2019 and a further 13,247 tCO2e credits in 2020 from:
▪ High to low bleed instrumentation conversion
▪ Converting fuel gas chemical pumps to solar driven
▪ Fuel gas to instrument air conversion
▪ Fuel gas instrumentation to solar powered instrumentation
Social:
▪ Spartan has implemented health and safety COVID-19 protocols into its operations
▪ Based on the WCB Industry 6300 for 2020, Spartan ranks 1 out of 256 employers in the Large Business Experience
Rating (ER) program (1)
Governance:
▪ Spartan is significantly aligned with shareholders with 13% Insider Ownership (basic)
▪ Diversity – 30% Female in Management Positions & 42% Female Workforce
Spartan Delta wellsite solar power generation
March 26, 2021 19
1) As per the Workers’ Compensation Board – Alberta Employer Report CardINDIGENOUS PARTNERSHIPS
Committed to Sustainable and Responsible Resource Development
O’Chiese First Nation:
▪ Spartan has a partnership with the O’Chiese First Nation based on
responsible development of oil & gas resources on the O’Chiese First
Nation lands
▪ Spartan prioritizes First Nation owned and operated business
with respect to its operations
▪ Spartan has created a soci-economic plan with the O’Chiese to
create long-term social benefits for the First Nation
Leading Environmental Stewardship on First Nation lands:
▪ Spartan, together with the O’Chiese First Nation, have created an
industry leading Abandonment & Reclamation Program to protect
Indigenous lands for future generations
▪ The ARO program outlines and commits Spartan to timely
abandonment & reclamation of all wells on the O’Chiese First
Nation lands
▪ Spartan has also committed to working with both the Saddle Lake
First Nation and Whitefish (Goodfish) Lake First Nation to abandon
and reclaim wells on First Nation lands
March 26, 2021 20MARKETING & RISK MANAGEMENT
High Torque to Strengthening AECO Fundamentals
Natural Gas Exposure – 100% AECO:
▪ Spartan is uniquely positioned with 100% exposure to AECO pricing,
and no economic burden of transport to underperforming markets
▪ Natural gas production is hedged approximately 28% in 2021
Natural Gas Fundamentals continue to be positive:
▪ Natural gas power generation is the largest component of the North
American power stack and will continue to grow as coal is phased out
Current Operating Capacity by Technology
Coal
Wind
Solar
Other
Nuclear
Natural Gas
Source: ARM Energy
▪ Alberta gas egress coupled with increasing Western Canadian
Sedimentary Basin gas demand paints an attractive story for AECO
versus other markets
March 26, 2021 21INVESTOR HIGHLIGHTS
Platform for Acquisitive Growth and Free Funds Flow Generation
Experienced team with a record of efficient capital discipline and value creation through consolidation
Material position in the Spirit River, Cardium and Montney, three of Canada’s most prolific plays
Two Core Areas – West-Central Alberta Deep Basin and Alberta Montney
Targeting internally funded organic growth and material free funds flow
Balance Sheet strength to fund further consolidation
Modern company with a clean operating platform and minimal ARO overhang
Owned infrastructure footprint provides opportunistic tuck-in consolidation potential
Deep inventory of economic drilling on strip pricing – active drilling program in 2021
March 26, 2021 22Appendix March 26, 2021 23
WEST-CENTRAL ALBERTA DEEP BASIN
Asset Quality Drives Top Tier Capital Efficiencies and Sustainable Free Funds Flow
▪ Targeting liquids-rich Spirit River and liquids-rich gas and oil Cardium
▪ Favorable subsurface properties:
Deep Basin
Fairway
✓ Situated in the over-pressured deep basin fairway
✓ Considerably higher liquids yield than most Spirit River assets Pembina
▪ Multiple stacked targets in the Spirit River provide significant
resource development opportunities, including maximizing recoveries
and surface pad synergies
▪ 10+ years of de-risked, highly economic Spirit River and Cardium Brazeau
locations across >130,000 (1) net acres of land in West-Central Alberta
A A’
100132304410W500 100030404509W500 100013304309W500
Gamma NPHI DPHI Gamma NPHI DPHI Gamma NPHI DPHI Alder Flats
A
Cardium Cardium Ferrier
A’
Willesden Green
Baptiste
Falher A Falher A
Falher B
Falher B
Wilrich
Wilrich
Spartan Lands O’Chiese First Nation Spirit River Well Cardium Well
March 26, 2021 24
1) As of December 31, 2020ANALYST COVERAGE & CONTACT INFORMATION
Institution Analyst EXECUTIVE OFFICE STOCK EXCHANGE LISTING
Spartan Delta Corp. The TSX Venture Exchange
ATB Capital Markets Patrick O’Rourke Trading Symbol: SDE.V
500, 207 – 9th Avenue SW
Calgary, Alberta T2P 1K3 INVESTOR INFORMATION
BMO Capital Markets Ray Kwan
P: 403 265 8011
W: www.spartandeltacorp.com Visit our website
Cormark Securities Garett Ursu
W: www.spartandeltacorp.com
TRANSFER AGENT or contact
Desjardins Capital Markets Chris MacCulloch Investor Relations
Odyssey Trust Inc. E: IR@spartandeltacorp.com
1230 – 300 - 5th Avenue SW
Eight Capital Phil Skolnick Calgary, Alberta T2P 3C4 CORPORATE CALENDAR
P: 587 885 0960
Haywood Capital Markets Christopher Jones May 14, 2021
AUDITORS First Quarter 2021 Results
National Bank Financial Dan Payne
PricewaterhouseCoopers LLP
Calgary, Alberta
Paradigm Capital Adam Gill
ENGINEERING CONSULTANTS
Peters & Co. Limited Dan Grager
McDaniel & Associates Consultants Ltd.
Calgary, Alberta
Raymond James Jeremy McCrea
LEGAL COUNSEL
Scotia Capital Cameron Bean
Stikeman Elliott LLP
Stifel - FirstEnergy Cody Kwong Calgary, Alberta
TD Securities Aaron Bilkoski
March 26, 2021 25MANAGEMENT TEAM & BOARD OF DIRECTORS
MANAGEMENT TEAM
Richard McHardy
➢ Former President, CEO and co-founder of Spartan Energy, Spartan Oil and Spartan Exploration
Executive Chairman & Director
Fotis Kalantzis
➢ Former SVP and co-founder of Spartan Energy, Spartan Oil and Spartan Exploration
President, CEO & Director
Geri Greenall
➢ Former CFO and co-founder, Camber Capital Corp., former Portfolio Manager & Chief Compliance Officer, Canoe Financial
CFO
Thanos Natras
➢ Former Geoscience Manager, Spartan Energy, former VP Exploration, Arcan Resources
VP Exploration
Craig Martin
➢ Former Manager D&C, Spartan Energy and Spartan Oil
VP Operations
Randy Berg
➢ Former VP Land, Spartan Energy, former VP Business Development & Land, Renegade Petroleum
VP Land
Mark Hodgson
➢ Former VP Operations, Obsidian Energy, former VP New Ventures & Country Manager, Bankers Petroleum
VP Corporate Development
Brendan Paton
➢ Director, Canoe Point Energy, former Production Engineer, Shell Canada
VP Engineering
Ashley Hohm
➢ Former VP Finance, Kelt Exploration, former Manager Financial Reporting, Celtic Exploration
VP Finance & Controller
INDEPENDENT BOARD OF DIRECTORS
➢ Former Director of Spartan Energy, Spartan Oil, and Spartan Exploration former President, Cypress Energy; Chairman &
Donald Archibald
CEO, Cequel Energy; President & CEO, Cyries Energy
➢ Former Director of Spartan Energy, Spartan Oil and Spartan Exploration former Chairman, President & CEO, Big Horn
Reg Greenslade
Resources, Enterra Energy, Enterra Energy Trust, JED Oil; President & CEO, Tuscany International Drilling
➢ Founder and a principal of KO Capital Advisors former Vice Chairman & Co-Head Energy Investment Banking, GMP
Kevin Overstrom
FirstEnergy
➢ Former SVP, Corporate and Business Development, Crescent Point Energy Director of Southern Energy Corp., and Equinor
Tamara MacDonald
Canada
➢ Former Chairman & CEO, New Age (African Global Energy) Ltd. former Executive Director & Officer, Marathon Oil and
Steve Lowden
Premier Oil
Elliot S. Weissbluth ➢ Former Chairman, Hightower Inc. former Founder, Director & President, U.S. Fiduciary
March 26, 2021 26SPARTAN ENERGY – SPARTAN OIL – SPARTAN EXPLORATION
Western Canada’s Best-in-Class Performer: Proven Low-Cost Operator
▪ From 2010 through 2018, Spartan assembled and developed
multiple high-quality assets throughout Central & Southern
Alberta and Southeast Saskatchewan
▪ Through infill horizontal development drilling and its
application of multi-stage frac technology, Spartan unlocked
significant resource potential in both light and tight oil plays
▪ Developed a deep inventory of highly economic light oil drilling
locations and waterflood projects capable of delivering
sustainable growth and free cash flow
▪ Focused capital on high quality, long life, operated, multi-zone
potential with existing infrastructure and capacity
▪ Spartan Exploration: grew production from ~400 boe/d to
~2,500 boe/d and sold to Penn West, outperforming the TSX
Energy Index by ~90%
▪ Spartan Oil: sold to Bonterra for ~$480 million in 2013 after
growing production to >4,000 boe/d
▪ Spartan Energy: sold to Vermilion Energy for C$1.4 billion in
2018 at a production level of 23,000 boe/d and independently
evaluated P+P reserves of 113.5 MMBoe
March 26, 2021 27THE SPARTAN DOMESTIC ADVANTAGE
Domestic Operational Track Record
From 2014 to its sale to Vermilion Energy, Spartan Energy Management’s ability to acquire and efficiently integrate assets
established itself as the lowest cost operator in the Southeast has been proven through past transaction activity
Saskatchewan area
▪ Average DCET costs for Mississippian wells below area peers at ▪ Management steadily reduced operating costs following two
$750k separate “acquisition cycles”
▪ Strong relationships with key service providers are intact and ▪ Spartan Energy completed 11 transactions (asset and corporate) in
ensure efficiencies through preferential rates and pre-existing just under a four-year time frame, more than any other
personnel corporation in the basin
Mississippian DCET Capex ($000’s) Spartan Energy - Operating Costs ($/boe)
$1,200 $22.00
$1,000 Acquisition OPEX
$1,000 $900 $920 $20.00
$800 $750 $18.00
$600 $16.00
$400 $14.00
$200 $12.00
$0 $10.00
Spartan Energy Company 1 Company 2 Company 3 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1
(1) Peer group includes Vermilion, TORC, and Crescent Point 2014 2015 2016 2017 2018
March 26, 2021 28SPARTAN ENERGY
263% Total Return and 33% CAGR | December 2013 – May 2018
Overview Relative Performance (Indexed to 100)
300
▪ Spartan Energy completed the recapitalization of Alexander Energy Spartan
in December 2013 and shortly after acquired Renegade Petroleum TSX Energy Post-recapitalization,
in March 2014 250 Spartan consistently
outperformed the TSX
Energy Index
▪ Over a 4-year period, management grew production from ~650 200
boe/d to ~22,750 boe/d through an acquisition and development
strategy
150
▪ During a period of significant uncertainty in the energy markets,
100
management stewarded capital efficiently and delivered above
market shareholder returns
50
Dec-13 Jun-14 Dec-14 Jun-15 Dec-15 Jun-16 Dec-16 Jun-17 Dec-17
Production Growth Cash Flow Growth
25,000 150.0 $60.0 $0.60
Cash Flow Per Share ($/mmsh.)
20,000 120.0
Production Per Share
Production (boe/d)
Cash Flow ($mm) $40.0 $0.40
(boe/d/mmsh.)
15,000 90.0
10,000 60.0
$20.0 $0.20
5,000 30.0
0 0.0 $0.0 $0.00
Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1
2014 2015 2016 2017 2018 2014 2015 2016 2017 2018
Cash Flow Cash Flow per Share
Total Production Production per Share
March 26, 2021 29HISTORICAL EV/DACF MULTIPLE COMPARISON
Spartan Energy Corp. vs Premium Light Oil Peers (1)
16.0x
Spartan Energy Corp.
Light Oil Peer Avg. (2)
14.0x The Spartan management team has
historically traded at, or above, the premium
light oil company average multiple (1)
12.0x
Fwd EV/NTM DACF Multiple (x)
10.0x
8.0x
6.0x
Light Oil Peer Avg.
4.0x
2.0x
Source: Factset Consensus Estimates (-)
March 26, 2021 30
1) Light Oil Peer Avg. includes: CPG, ERF, RRX, SGY, TOG, TVE, WCP
2) Comparable EV/NTM DACF period subject to Factset broker estimate availability (May 9, 2014 to the close of the acquisition of
Spartan Energy Corp. by Vermilion Energy Inc. on May 28, 2018)SPARTAN OIL
268% Total Return and 128% CAGR | June 2011 – January 2013
Overview Relative Performance (Indexed to 100)
250
▪ Formed through the spin-out of certain Cardium assets and SE Spartan
As a public company, Spartan
Saskatchewan assets from Spartan Exploration TSX Energy outperformed the TSX Energy
Index by ~130%
200
▪ Spartan continued to consolidate its position in the Pembina
Cardium, where it successfully built a large contiguous land
position and drilled 80 gross wells with 100% success rate
150
▪ In less than two years, Spartan Oil grew production per share
>500% and cash flow per share >1,000%
100
▪ Announced its sale to Bonterra in December 2012 at top decile
metrics
50
Jun-11 Sep-11 Dec-11 Mar-12 Jun-12 Sep-12 Dec-12
Production Growth Cash Flow Growth
5,000 60.0 $25.0 $0.30
Cash Flow Per Share ($/mmsh.)
4,000 48.0 $20.0 $0.24
Production Per Share
Production (boe/d)
Cash Flow ($mm)
(boe/d/mmsh.)
3,000 36.0 $15.0 $0.18
2,000 24.0 $10.0 $0.12
1,000 12.0 $5.0 $0.06
0 0.0 $0.0 $0.00
Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q2 Q3 Q4 Q1 Q2 Q3 Q4
2011 2012 2011 2012
Production Production per Share Cash Flow Cash Flow per Share
March 26, 2021 31SPARTAN EXPLORATION
573% Total Return and 80% CAGR | January 2010 – May 2011
Overview Relative Performance (Indexed to 100)
250
▪ Spartan Exploration was formed in Q1-2008 with a view of Spartan
targeting tight oil resources plays in western Canada
TSX Energy As a public company,
Spartan outperformed the
200 TSX Energy Index by ~90%
▪ Spartan accumulated Cardium, Bakken and Shaunavon assets
throughout 2008 and 2010 followed by a reverse takeover (RTO)
recap transaction of a TSX listed shell company
150
▪ From the RTO transaction in Q1-2010 to its sale in Q1-2011,
Spartan grew production from ~400 boe/d to ~2,500 boe/d 100
delivering production per share growth of >425% and cash flow per
share growth of >650%
50
Jan-10 Apr-10 Jul-10 Oct-10 Jan-11 Apr-11
Production Growth Cash Flow Growth
3,000 90.0 $14.0 $0.35
Cash Flow Per Share ($/mmsh.)
2,500 75.0 $12.0 $0.30
Production Per Share
Production (boe/d)
Cash Flow ($mm)
$10.0 $0.25
(boe/d/mmsh.)
2,000 60.0
$8.0 $0.20
1,500 45.0
$6.0 $0.15
1,000 30.0
$4.0 $0.10
500 15.0 $2.0 $0.05
0 0.0 $0.0 $0.00
Q1 Q2 Q3 Q4 Q1 Q1 Q2 Q3 Q4 Q1
2010 2011 2010 2011
Production Production per Share Cash Flow Cash Flow per Share
March 26, 2021 32DISCLAIMER
Forward Looking Statements effect on Spartan. While the precise impact of the COVID-19 virus on Spartan remains unknown,
▪ Certain information included in this presentation constitutes forward-looking information under rapid spread of the COVID-19 virus may have a material adverse effect on global economic
applicable securities legislation. Forward looking information typically contains statements with activity, and can result in volatility and disruption to global supply chains, operations, mobility of
words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", "project" or people and the financial markets, which could affect interest rates, credit ratings, credit risk,
similar words suggesting future outcomes or statements regarding an outlook. Forward-looking inflation, business, financial conditions, results of operations and other factors relevant to
information in this presentation may include, but is not limited to, statements about: corporate Spartan. Please refer to the Spartan's most recent Annual Information Form and MD&A for
strategy, objectives, strengths and focus of Spartan; the intentions of management and Spartan additional risk factors relating to Spartan, which can be accessed either on Spartan's website at
with respect to its growth strategy and business plan; Spartan's expectations regarding its www.spartandeltacorp.com or under the Company's profile on www.sedar.com. Readers are
2020/2021 drilling program, including the location of wells, scheduled drilling dates and the timing cautioned not to place undue reliance on this forward-looking information, which is given as of the
of expected pay out from such wells; Spartan's intentions to maintain balance sheet flexibility to date hereof, and to not use such forward-looking information for anything other than its intended
allow Spartan to take advantage of future opportunities; Spartan's acquisition and consolidation purpose. Spartan undertakes no obligation to update publicly or revise any forward-looking
strategy and targets; Spartan plans to deliver strong operational performance and reduce debt; information, whether as a result of new information, future events or otherwise, except as
Spartan's production forecasts; Spartan 2021 guidance and budget, including anticipated capital required by law.
expenditures and Spartan's ability to fund capital expenditures through operating activities; ▪ The forward-looking information contained in this presentation is made as of the date hereof and
Spartan's cost-cutting measures and the results thereof; Spartan's ESG initiative; predictions Spartan undertakes no obligation to update publicly or revise any forward-looking information,
regarding commodities pricing and industry fundamentals, including natural gas demand and whether as a result of new information, future events or otherwise, unless required by applicable
supply; the continuation of Spartan's strategic partnerships, and expected benefits therefrom. securities laws. The forward looking information contained in this presentation is expressly
Statements relating to "reserves" are also deemed to be forward looking statements, as they qualified by this cautionary statement.
involve the implied assessment, based on certain estimates and assumptions, that the reserves
described exist in the quantities predicted or estimated and that the reserves can be profitably ▪ FOFI. This presentation contains future-oriented financial information and financial outlook
produced in the future. information (collectively, "FOFI") about Spartan's prospective results of operations, production,
working capital, capital efficiency, sustaining capital, capital expenditures, enterprise value,
▪ The forward-looking statements contained in this presentation are based on certain key recycle ratio, payout, operating netback, share price, investment yield, net debt (surplus),
expectations and assumptions made by Spartan, including expectations and assumptions adjusted free funds flow, free funds flow, NPV10, NOI, IRR, return of capital, operating costs,
concerning the performance of Spartan's management team and board, the success of future cost reductions and components thereof, all of which are subject to the same assumptions, risk
drilling, development and completion activities, the performance of existing wells, the factors, limitations and qualifications as set forth in the above paragraphs. FOFI contained in this
performance of new wells, the availability and performance of facilities and pipelines, the presentation was approved by management of the date of this presentation and was provided for
geological characteristics of Spartan's properties, the successful application of drilling, completion the purpose of providing further information about Spartan's anticipated future business
and seismic technology, prevailing weather and break-up conditions and access to drilling operations. Spartan disclaims any intention or obligation to update or revise any FOFI contained
locations, commodity prices, price volatility, price differentials and the actual prices received for in this presentation, whether as a result of new information, future events or otherwise, unless
products, royalty regimes and exchange rates, the application of regulatory and licensing required pursuant to applicable law. Readers are cautioned that the FOFI contained in this
requirements, the availability of capital, labour and services, Spartan's ability to complete planned presentation should not be used for purposes other than for which it is disclosed herein.
capital expenditures within budgeted cost estimates, the ability to market oil and gas successfully,
Spartan's ability to integrate assets and employees acquired through acquisitions and the ▪ Third Party Information. Certain information contained herein has been obtained from published
creditworthiness of industry partners. sources prepared by independent industry analysts and third-party sources (including industry
publications, surveys and forecasts). While such information is believed to be reliable for the
▪ Although Spartan believes that the expectations and assumptions on which the forward-looking purpose used herein, none of the directors, officers, owners, managers, partners, consultants,
statements are based are reasonable, undue reliance should not be placed on the forward- shareholders, employees, affiliates or representatives assumes any responsibility for the
looking statements because Spartan can give no assurance that they will prove to be correct. accuracy of such information. Some of the sources cited in this presentation have not consented
Since forward-looking statements address future events and conditions, by their very nature they to the inclusion of any data from their reports, nor has Spartan sought their consent.
involve inherent risks and uncertainties. Actual results could differ materially from those currently
anticipated due to a number of factors and risks. These include, but are not limited to, stock
market volatility, risks associated with the oil and gas industry in general (e.g., operational risks in
development, exploration and production; the uncertainty of reserve estimates; the uncertainty of
estimates and projections relating to production, costs and expenses and health, safety and
environmental risks), incorrect assessment of the value of acquisitions, failure to complete or
realize the benefits of acquisitions, constraint in the availability of services, commodity price and
exchange rate fluctuations, actions of OPEC and OPEC+ members, changes in legislation
(including but not limited to tax laws, royalty regimes and environmental legislation), adverse
weather or break-up conditions and uncertainties resulting from potential delays or changes in
plans with respect to exploration or development projects or capital expenditures. Production
forecasts are directly impacted by commodity prices and the actual timing of our capital
expenditures. Actual results may vary materially from forecasts due to changes in interest rates,
oil differentials, exchange rates and the timing of expenditures and production additions. In
addition, Spartan cautions that current global uncertainty with respect to the spread of the
COVID-19 virus and its effect on the broader global economy may have a significant negative
March 26, 2021 33DISCLAIMER CONT’D
Oil and Gas Advisories
▪ BOE Disclosure. The term barrels of oil equivalent ("boe") may be misleading, particularly if used ▪ "Undeveloped F&D costs" are calculated as the sum of development capital, divided by the
in isolation. A BOE conversion ratio of six thousand cubic feet of natural gas to barrels of oil undeveloped reserves at the proved undeveloped and proved plus probable undeveloped levels.
equivalence is based on an energy equivalency conversion method primarily applicable at the ▪ "Operating netback" see "Reader Advisories – Non-GAAP Measures".
burner tip and does not represent a value equivalency at the wellhead. All BOE conversions in
this presentation are derived from converting gas to oil in the ratio mix of six thousand cubic feet ▪ "Recycle ratio" is measured by dividing operating netback by F&D cost per boe for the year.
of gas to one barrel of oil. ▪ "Payout" is achieved when revenues, less royalties, production and transportation costs are
▪ Product Types. Throughout this presentation, "crude oil" or "oil" refers to light and medium crude equal to the total capital costs associated with drilling, completing, equipping and tying in a well.
oil product types as defined by NI 51-101. Condensate is a natural gas liquid as defined by Management considers payout an important measure to evaluate its operational performance and
National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). capital allocation processes. It demonstrates the return of cash flow and allows Spartan to
References to "natural gas liquids" or "NGLs" throughout this presentation comprise pentane, understand how a capital program is funded under different operating scenarios, which helps
butane, propane, and ethane, being all NGLs as defined by NI 51-101 other than condensate, assess Spartan's ability to generate value.
which is disclosed separately because the value equivalency of condensate is more closely ▪ "Finding and development (F&D) cost" is the sum of capital expenditures incurred in the period
aligned with crude oil. References to "natural gas" or "gas" relates to conventional natural gas. and the change in future development capital ("FDC") required to develop reserves. F&D cost per
▪ Reserves Disclosure. All reserves information in this presentation was prepared by McDaniel & BOE is determined by dividing current period net reserve additions into the corresponding
Associates Consultants Ltd. ("McDaniel") effective December 31, 2020 (the "McDaniel Report") period's F&D cost. Readers are cautioned that the aggregate of capital expenditures incurred in
using average forecast pricing of McDaniel, GLJ Ltd. ("GLJ") and Sproule Associates Limited the year, comprised of exploration and development costs and acquisition costs, and the change
("Sproule") in accordance with NI 51-101 and the Canadian Oil and Gas Evaluation Handbook in estimated FDC generally will not reflect total FD&A costs related to reserves additions in the
(the "COGE Handbook"). Reserves information in relation to the Acquisitions was prepared by: year.
(a) Sproule effective December 31, 2019, regarding the Inception assets; and (b) GLJ effective ▪ "IP30" is the initial production from a well for the first 720 hours (30 days) based on
October 1, 2020, regarding the Simonette assets, in accordance with NI 51-101 and the COGE operating/producing hours.
Handbook. The estimates of reserves in this presentation do not include reserves attributed to the
newly acquired Willesden Green assets. The estimates of reserves and future net revenue for the ▪ "IP60" is the initial production from a well for the first 1,440 hours (60 days) based on
assets to be acquired pursuant to the Acquisitions may not reflect the same confidence level as operating/producing hours.
estimates of reserves and future net revenue for all of Spartan's properties, due to the effects of ▪ "NPV10" is the anticipated net present value of the future net operating income after capital
aggregation. While the above referenced reserves reports use different forecasted pricing and expenditures, discounted at a rate of 10% (before tax).
cost assumptions as of their respective effective dates, Spartan has performed sensitivity ▪ Type Curves. The reservoir engineering and statistical analysis methods utilized is broad and can
analysis on such assumptions and has determined that variances in reserves values due to the include various methods of technical decline analyses, and reservoir simulation all of which are
different effective dates do not lead to materially misleading results when reserves are disclosed generally prescribed and accepted by the COGE Handbook and widely accepted reservoir
on a pro-forma basis. Given the foregoing, management believes that pro-forma estimates of engineering practices. These type curves were generated by McDaniel, an independent qualified
reserves disclosed herein are not misleading with respect to assumptions, input data and the reserves evaluator. These type curves incorporate the most recent data from actual well results
professional judgment of the qualified reserves evaluators. All reserve references in this and would only be representative of the specific drilled locations. There is no guarantee that
presentation are "Company share reserves". Company share reserves are the applicable Spartan will achieve the estimated or similar results derived therefrom.
company's total working interest reserves before the deduction of any royalties and including any
royalty interests payable to the company. It should not be assumed that the present worth of ▪ Drilling Locations / Inventory. This presentation discloses drilling inventory in three categories: (i)
estimated future amounts presented in the tables above represents the fair market value of the proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and
reserves. There is no assurance that the forecast prices and costs assumptions will be attained, probable locations are derived from the McDaniel Report and account for drilling locations that
and variances could be material. The recovery and reserve estimates of the crude oil, natural gas have associated proved and/or probable reserves, as applicable. Unbooked locations are internal
liquids and natural gas reserves provided herein are estimates only and there is no guarantee estimates based on our prospective acreage and an assumption as to the number of wells that
that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids can be drilled per section based on industry practice and internal review. Unbooked locations do
reserves may be greater than or less than the estimates provided herein. All evaluations and not have attributed reserves or resources. Of the 864 (590 net) total drilling locations identified
summaries of future net revenue are stated prior to the provision for interest, debt service herein, 75 (63 net) are proved locations, 43 (38 net) are probable locations and 746 (489 net) are
charges or general and administrative expenses and after deduction of royalties, operating costs, unbooked locations. Of the 118 (101 net) FDC drilling locations identified herein, 75 (63 net) are
estimated well abandonment and reclamation costs and estimate future capital expenditures. proved locations, and 43 (38 net) are probable locations. Unbooked locations have been
identified by management as an estimation of our multi-year drilling activities based on evaluation
▪ Oil and Gas Metrics. This presentation contains metrics commonly used in the oil and natural gas of applicable geologic, seismic, engineering, production and reserves information. There is no
industry which have been prepared by management, such as "development capital", "F&D costs", certainty that we will drill all unbooked drilling locations and if drilled there is no certainty that such
"operating netback", "recycle ratio", "payout", "F&D costs", "IP90" and "NPV10". These terms do locations will result in additional oil and gas reserves, resources or production. The drilling
not have a standardized meaning and may not be comparable to similar measures presented by locations on which we drill wells will ultimately depend upon the availability of capital, regulatory
other companies, and therefore should not be used to make such comparisons. Management approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional
uses these oil and gas metrics for its own performance measurements and to provide reservoir information that is obtained and other factors. While certain of the unbooked drilling
shareholders with measures to compare our operations over time. Readers are cautioned that the locations have been de-risked by drilling existing wells in relative close proximity to such
information provided by these metrics, or that can be derived from the metrics presented in this unbooked drilling locations, other unbooked drilling locations are farther away from existing wells
presentation, should not be relied upon for investment or other purposes. where management has less information about the characteristics of the reservoir and therefore
▪ "Development capital" means the aggregate exploration and development costs incurred in the there is more uncertainty whether wells will be drilled in such locations and if drilled there is more
financial year on reserves that are categorized as development. Development capital excludes uncertainty that such wells will result in additional oil and gas reserves, resources or production.
capitalized administration costs.
March 26, 2021 34You can also read
